Seismic Acquisition in Marine Environments Using Survey Paths Following a Series of Linked Deviated Paths and Methods of Use

ABSTRACT

Methods and systems are provided for acquiring seismic data in a marine environment using survey paths following a series of linked curved paths so as to obtain multi-azimuthal data over a sub-surface target. Marine vessels towing multiple seismic streamers may be configured to travel substantially along a series of linked deviated paths or a series of linked curved paths. Sources may be excited to introduce acoustic wave energy in the marine environment and into the subsea region. The acoustic wave energy then reflects and refracts from the subsea region to form reflected and refracted wave energy, which is detected by seismic receivers spaced along the streamers. The detected seismic data is then interpreted to reveal seismic information representative of the surveyed subsea region. Other enhancements include configuring the streamers in a flared configuration, where the lateral spacing increases rearwardly over the length of the seismic streamers.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional application of U.S. application Ser.No. 12/940,568, filed Nov. 5, 2010, entitled “Seismic Acquisition inMarine Environments Using Survey Paths Following a Series of LinkedDeviated Paths and Methods of Use”, which claims the benefit of andpriority to U.S. Provisional Application Ser. No. 61/260,154 filed Nov.11, 2009, entitled “Seismic Acquisition in Marine Environments UsingSurvey Paths Following a Series of Linked Deviated Paths and Methods ofUse,” which are both hereby incorporated by reference in their entirety.

FIELD OF THE INVENTION

The present invention relates generally to a method and system foracquisition of seismic data in a marine environment. More particularly,but not by way of limitation, embodiments of the present inventioninclude methods and systems for acquiring seismic data in a marineenvironment using survey paths following a series of linked deviatedpaths or linked curved paths.

BACKGROUND

Marine seismic exploration investigates and maps the structure andcharacter of subsurface geological formations underlying a body ofwater. Marine seismic data is typically gathered by towing seismicsources (e.g., air guns) and seismic receivers (e.g., hydrophones)through a body of water behind one or more marine vessels. As theseismic sources and receivers are towed through the water, the seismicsources generate acoustic energy that travel through the water and intothe earth, where they are reflected and refracted by interfaces betweensubsurface geological formations. The seismic receivers detect theresulting reflected and refracted energy, thus acquiring seismic datathat provides seismic information about the geological foundationsunderlying the body of water.

Typically, large arrays of seismic receivers, often numbering in thethousands, are used to gather marine seismic data. The seismic receiversare generally attached to and spaced apart along streamer cables thatare towed behind a marine vessel.

By way of illustration of such a system, FIG. 1 shows a simplifieddepiction of a conventional marine seismic data acquisition systememploying a marine vessel 10 to tow seismic sources 12 and a system 14of steerable seismic streamers 16 through a body of water 18.

Each of seismic streamers 16 includes a streamer cable 20, a series ofseismic receivers 22 and a series of steering devices 24 coupled tocable 20. Relative positions of the marine seismic receivers duringseismic data acquisition can affect the quality and utility of theresulting seismic data. However, unpredictable environmental forces suchas currents, winds, and sea states present in many marine environmentscan cause the relative positions of marine seismic receivers to varygreatly as they are towed through the water. Therefore, it is common forsteering devices (commonly know as “birds”) to be attached to thestreamer cables so that the relative positions (both lateral andvertical) of the seismic receivers can be controlled as they are towedthrough the water. As depicted in FIG. 1, during conventional marineseismic acquisition, steering devices 24 are used to maintainsubstantially constant lateral spacing between seismic streamers 16.

As a further illustration of typical marine seismic systems, FIG. 2illustrates a side view of marine vessel 10 towing one or more streamers12 having seismic sources 12 ( ) and/or seismic receivers 22 (O) throughbody of water 18 to acquire seismic data for a subterranean geologicalformation region of interest 26 of geological formation 25.

As marine vessel 10 tows seismic sources 12 and receivers 22 throughbody of water 18, seismic sources 12 are simultaneously excited, whichgenerate acoustic wave energy that propagates down through water 18 andinto geological formation 25. The acoustic wave energy is then reflectedand refracted by interfaces between strata of geological formation 25.The resulting reflected/refracted seismic energy then passes upwardlythrough water 18 and is detected by seismic receivers 22. Additionalpasses are then conducted to survey additional points of interest. Theseismic data detected by seismic receivers 22 then provides seismicinformation representative of subterranean geological formation ofinterest 26.

A common problem encountered with conventional marine seismic surveys is“gaps” in the acquired seismic data. These data gaps can occur when thespacing between adjacent acquisition passes is too large to providesufficient resolution for proper data processing. Gaps in seismic datacan be caused by a number of factors including, for example, skewing ofthe seismic streamers relative to the direction of travel of the towingvessel during data acquisition. Even when steerable streamers areemployed, gaps in seismic data are common, particularly when strongcrosscurrents are present. When strong crosscurrents are present duringseismic data acquisition, it is not practical to maintain all thestreamers in desired orientation, because fighting strong crosscurrentswith steering devices may produce noise that dramatically reduces thequality of the gathered seismic data.

When gaps in marine seismic data are discovered, if the data gaps cannotbe filled by post-acquisition interpolation methods, the areascorresponding to the data gaps must be resurveyed, a process commonlyknown as “shooting in-fill” or “in-filling.” Unfortunately, theexistence of gaps in marine seismic data may not be discovered until theinitial marine seismic survey has been completed and the resultingseismic data is being processed. Obviously, in-filling is highlyundesirable because of the significant expense and time involved inresurveying in-fill areas that may be located hundreds of kilometersfrom one another or even retransiting the same vessel pass again to makeup coverage.

Traditionally, marine seismic surveys using the systems depicted inFIGS. 1 and 2 above are conducted using a series of straight line sailpaths across a region on interest. That is, under conventional methods,a marine vessel and its corresponding streamers sail back and forthacross a geological region of interest, incrementally moving eachsubsequent pass or sweep over slightly until all of the combined pathshave covered the survey region of interest. In this way, traditionalseismic surveys follow a survey path similar to the path followed by onemowing a rectangular section of lawn with a lawn mower, namely, a backand forth straight line path that is moved over incrementally each passuntil the entire section of lawn is covered.

Referring again to FIG. 1, traditional marine seismic survey systemsemploy a set of streamers where the lateral distance (d_(f)) of theforward-most seismic receivers is equivalent to the lateral distance(d_(r))) of the rearwardly-most seismic receivers. Thus, in surveying aregion of interest, a marine vessel 10 will typically employ a back andforth path across a geological region of interest, moving each pass orsweep over by roughly a distance of ½ d_(f) to a distance of about 1d_(f) until the entire region of interest is surveyed. As will be seenbelow, this method of surveying suffers from a poor randomization anddistribution of source point locations and receivers throughout thesurvey area. For example, for a ten streamer setup with dual sourcestowed by the streamer vessel, d_(f) might be about 900 m but each sailline would move over about 500 m. Accordingly, this poor randomizationand distribution results in a decreased effectiveness ofpost-acquisition interpolation methods for filling in seismic data gapsin the acquired data.

Consequently, this method of surveying with a series of straight pathsacross a region is a highly inefficient way of gathering off-set andazimuth distributions. Using conventional methods to acquire wideazimuth distributions requires multiple passes down the same line withmultiple boats, usually a single streamer vessel and multiple sourcevessels or two streamer vessels and multiple source vessels. Even usingmultiple passes and multiple vessels, the azimuth distribution acquiredis still limited in certain directions. In this way, conventionalmethods of seismic surveys fail to provide full offset and azimuth dataand further fail to optimize the randomization of the offset and azimuthdata available. Accordingly, conventional methods of surveying a regionare unnecessarily more costly in terms of both time and direct surveycosts. Indeed, the cost of acquiring wide-azimuth data essentiallyincreases by the cost of the number of passes required down each sailline to obtain the azimuth range required. For conventional marinesurveys that are not wide azimuth, costs can be increased by as much as50% by infill needs.

Accordingly, there is a need in the art for improved seismic surveymethods and systems that address one or more disadvantages of the priorart.

SUMMARY

The present invention relates generally to a method and system foracquisition of seismic data in a marine environment. More particularly,but not by way of limitation, embodiments of the present inventioninclude methods and systems for acquiring seismic data in a marineenvironment using survey paths following a series of linked deviatedpaths or linked curved paths.

One example of a method for acquiring seismic data for a subsea regionof the earth comprising the steps of: providing a marine vessel and aplurality of seismic streamers, wherein the plurality of seismicstreamers are coupled to the marine vessel for towing, wherein eachseismic streamer comprises a plurality of marine seismic receiversspaced apart along the length of each seismic streamer; providing one ormore marine seismic sources; introducing the marine seismic sources intoa marine environment in range of the marine seismic receivers; towingthe seismic streamers through the marine environment such that themarine vessel and the seismic streamers travel substantially along afirst series of linked curved paths; exciting at least one of the marineseismic sources simultaneously with the step of towing the seismicstreamers so as to cause acoustic wave energy to travel through themarine environment into the subsea region of the earth; allowing theacoustic wave energy to reflect and refract from the subsea region so asto form reflected and refracted wave energy; and detecting the reflectedand refracted wave energy with the marine seismic receivers so as toform detected seismic data.

The seismic streamers may optionally be configured in a flaredconfiguration. In certain embodiments, the seismic streamers may besteerable so as to achieve various desired streamer configurations.

Suitable examples of series of linked curved paths may include aplurality of half-ellipses, a plurality of alternating or invertedhalf-ellipses, sinusoidal wave paths, a plurality of linked half-sinewaves, a plurality of linked inverted half-sine waves. In certainembodiments, the survey path may form a sinusoidal wave having asubstantially constant wavelength.

The lengths of the seismic streamers may vary, some configurationsextending to a length at least as long as a quarter of the wavelength ofthe sinusoidal wave or to a length at least as long as half a wavelengthof the sinusoidal wave.

Where the survey paths are comprised of a plurality of half-ellipsesthat are substantially identical in shape, the length of the seismicstreamers may have a length at least as long as a length circumscribedby half of one of the half-ellipses or at least as long as the lengthcircumscribed by one of the half-ellipses.

In certain embodiments, the survey paths of the marine vessel and theseismic streamers may follow a series of deviated survey paths. Examplesof suitable deviated survey paths include triangle survey paths, squarewave survey paths, or any combination thereof

The features and advantages of the present invention will be apparent tothose skilled in the art. While numerous changes may be made by thoseskilled in the art, such changes are within the spirit of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present disclosure and advantagesthereof may be acquired by referring to the following description takenin conjunction with the accompanying figures, wherein:

FIG. 1 illustrates a simplified overhead depiction of a conventionalmarine seismic acquisition system where the lateral spacing between thestreamers is substantially constant over the entire length of thestreamers.

FIG. 2 illustrates a side view of a marine vessel towing a plurality ofmarine seismic sources and a plurality of marine seismic receivers forconducting seismic surveys of a subsea region of the earth.

FIG. 3 illustrates an exemplary pair of sinusoidal or elliptical vesselsurvey paths that may be traversed with one or more marine streamervessels in accordance with one embodiment of the present invention.

FIG. 4 illustrates, for comparison purposes, examples of variouspossible sail line survey paths, namely a straight sail line, asinusoidal sail line, and a possible actual vessel path on a sail line.

FIG. 5 illustrates a simplified overhead depiction of a marine seismicacquisition system where the lateral spacing between the streamersincreases rearwardly over the length of the seismic streamers.

FIG. 6 illustrates a simplified overhead depiction of a marine seismicacquisition system with seismic streamers shown in aflared-configuration and more specifically, illustrating atrumpet-shaped system of variable length seismic streamers exhibitinglateral streamer spacing that increases rearwardly at an increasing rateover the length of the seismic streamers.

FIGS. 7A-7D illustrates additional sail line survey paths in accordancewith various embodiments of the present invention.

While the present invention is susceptible to various modifications andalternative forms, specific exemplary embodiments thereof have beenshown by way of example in the drawings and are herein described indetail. It should be understood, however, that the description herein ofspecific embodiments is not intended to limit the invention to theparticular forms disclosed, but on the contrary, the intention is tocover all modifications, equivalents, and alternatives falling withinthe spirit and scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION

The present invention relates generally to a method and system foracquisition of seismic data in a marine environment. More particularly,but not by way of limitation, embodiments of the present inventioninclude methods and systems for acquiring seismic data in a marineenvironment using survey paths following a series of linked deviatedpaths or linked curved paths.

Methods and systems are provided for acquiring multi-azimuthal data overa sub-surface target. In certain embodiments, a marine vessel towingmultiple seismic streamers may be configured to travel substantiallyalong a series of deviated linked paths or linked curved paths, whichmay optionally take the form of a series of linked half-ellipses, linkedhalf-sinusoidal waves, other linked curved paths, or any combinationthereof. In some embodiments, the survey paths of the marine vessel andits corresponding seismic streamers substantially form a sinusoidalwave. As the marine vessel travels along the series the linked curvedpaths, one or more sources may be excited so as to introduce acousticwave energy in the marine environment and subsequently into the subsearegion of the earth. The acoustic wave energy then reflects and refractsfrom the subsea region so as to form reflected and refracted waveenergy, which is detected by marine seismic receivers that are spacedalong the length of the seismic streamers. The detected seismic data isthen interpreted to reveal seismic information representative of thesurveyed subsea region of the earth.

Advantages of certain embodiments of the present invention include, butare not limited to, a reduction of the number of marine vessel runs orpaths required to complete a survey area, increased survey efficiencyand coverage, a more effective randomization of the locations of sourcepoint and receivers throughout the area, a reduction of the acquisitionfootprint in the final processed data, an increase of the effectivenessof post-acquisition interpolation methods used to fill holes or gaps inthe acquired data, lower survey costs, decreased survey times, andmaximization of the available offset and wide azimuth data.

Other enhancements to the methods herein include, but are not limitedto, configuring the streamers in a flared configuration, wherein thelateral spacing increases rearwardly over the length of the seismicstreamers or a trumpet-shaped system of variable length seismicstreamers exhibiting lateral streamer spacing that increases rearwardlyat an increasing rate over the length of the seismic streamers. U.S.patent application Ser. No. 12/167,683, filed Jul. 3, 2008, titled“Marine Seismic Acquisition with Controlled Streamer Flaring,” theentire disclosure of which is incorporated by reference, describes anumber of possible streamer configurations, streamer elements, anddevices, all of which may be used in combination with embodiments of thepresent invention.

Many other variations are possible as described in further detail below.For example, one or more additional marine vessels also towing seismicstreamers may be used in cooperation with the first marine vessel toform any portion of the series of linked curved paths.

Reference will now be made in detail to embodiments of the invention,one or more examples of which are illustrated in the accompanyingdrawings. Each example is provided by way of explanation of theinvention, not as a limitation of the invention. It will be apparent tothose skilled in the art that various modifications and variations canbe made in the present invention without departing from the scope orspirit of the invention. For instance, features illustrated or describedas part of one embodiment can be used on another embodiment to yield astill further embodiment. Thus, it is intended that the presentinvention cover such modifications and variations that come within thescope of the invention.

FIG. 3 illustrates an exemplary pair of sinusoidal or elliptical vesselsurvey paths that may be traversed by one or more marine streamervessels in accordance with one embodiment of the present invention. Asdescribed above with respect to FIGS. 1 and 2, surveying a region ofinterest with a series of straight line paths is an inefficient methodof gathering seismic data.

Rather, it has been discovered that surveying using a series of linkeddeviated paths or a series of curved linked paths results in a far moreefficient randomization of seismic source and receiver locations andangles, which increases the efficiency and effectiveness ofpost-acquisition interpolation methods. Examples of survey paths inaccordance with the present invention are shown in FIG. 3. For example,survey path 310 is survey path in the form of a sinusoidal wave. Surveypath 320 is a survey path also in the form of a sinusoidal wave butinverted with respect to survey path 310.

Here, first marine vessel 311 follows survey path 310, whereas secondmarine vessel 321 follows survey path 320. In this way, each marinevessel 311 and 321 follow survey paths that are sinusoidal and invertedwith respect to one another.

First marine vessel 311 tows seismic sources 313 and seismic streamers315. Likewise, second marine vessel 321 tows seismic sources 323 andseismic streamers 325. As each marine vessel 311 and 321 follow eachsurvey path 311 and 321, the paths travelled by their correspondingseismic streamers 315 and 325 also travel substantially alongapproximately the same respective survey paths, making allowances forwind and ocean current influences, which may perturb the positions ofseismic streamers 315 and 325 despite the corrections offered by theirrespective steering mechanisms, which attempt to correct for theseexternal influences.

In this way, the azimuth angles between the receivers and the sourcesconstantly vary throughout each survey path as each marine vesselprogresses along each sinusoidal survey path. These varying anglesresult in an effective randomization of the offset and azimuth seismicdata detected.

Many variations of the above method are possible. Survey paths 311 and321 may be circumscribed by one marine vessel acting alone or by two ormore marine vessels surveying in cooperation with one another. Anynumber of vessels could conduct a survey along any portion of surveypaths 311 and 321 such that the combination of all individual surveypaths covers the entirety of survey paths 311 and/or 321.

In certain embodiments, an optional marine vessel such as optionalmarine vessel 330 may be introduced to provide a stationary or movingseismic source or sources 333 as desired. These additional seismicsources 333 may be in addition to seismic sources 313 and 323 or inalternative to seismic sources 313 and 323. Seismic sources 313, 323,and 333 may be introduced to any location within range of any seismicdetectors being used to detect reflected and refracted acoustic waveenergy from seismic sources 313, 323, and 333.

Alternatively, a marine vessel could follow upper alternate survey path340, which is a series of linked half-sine waves, while another marinevessel follows lower alternative survey path 360. As before, either orboth of these paths could be surveyed by any number of marine vesselsacting in cooperation with one another, with each vessel surveyingnon-overlapping or overlapping portions of each survey path 340 and 360.

Where multiple seismic marine vessels cooperate with one another tocomplete a shared survey, it is explicitly recognized that these vesselsmay operate simultaneously with one another, sequentially with oneanother, time-lagged off-set with one another, or any combinationthereof.

FIG. 4 illustrates, for comparison purposes, examples of variouspossible sail line survey paths, namely a straight sail line, asinusoidal sail line, and a possible actual vessel path on a sail line.Sail line 410 is an example of a conventional survey path, which suffersfrom, among other things, a lack of diversity and randomization ofoffset and azimuth data. Sinusoidal sail line 420 represents an exampleof an ideal sail line survey path that results in a wider sampling andscattering of locations and of source points and receivers throughoutthe survey area. Actual vessel path on sail line 430 represents anactual vessel path that a vessel might travel when attempting to followsail path line 420 due to countervailing winds, ocean currents, andother environmental factors.

Marine seismic streamer systems may employ in the range of about 2 toabout 100 individual seismic streamers, in the range of about 4 to about50 individual seismic streamers, or in the range of about 5 to about 25individual seismic streamers. At least two of the seismic streamers 36may have a length in the range of about 0.5 to about 30 kilometers, inthe range of about 2 to 20 about kilometers, or in the range of about 4to about 12 kilometers. In one embodiment, at least one-half of theseismic streamers employed in the seismic streamer system may have alength within one or more of the above-recited ranges. In anotherembodiment, all of the seismic streamers employed in the seismicstreamer system have a length within one or more of the above-recitedranges.

In certain embodiments, the length of the seismic streamer may vary fromat least about ¼ of a wavelength, to at least about ½ of a wavelength,or to at least about a wavelength of the sinusoidal survey path. Byincreasing the length of the seismic streamer to correspond to a minimumlength of the sinusoidal survey path, a certain level of offset andazimuth diversity and randomization can be assured as a result of thesource and receiver locations as the seismic streamers travel along thesurvey path.

FIG. 5 illustrates a simplified overhead depiction of a marine seismicacquisition system useful in combination with certain embodiments of thepresent invention. Here, the lateral spacing between streamers increasesrearwardly over the length of the seismic streamers, also known as aflared configuration. This flared configuration is especiallyadvantageous when used in combination with seismic survey pathsfollowing a series of linked curved paths such as those described above.

Here, marine vessel 30 tows marine seismic system 34 through body ofwater 18. Marine seismic system comprises seismic sources 32 and seismicstreamers 36. Seismic streamers 36 in turn comprise cables 38, seismicreceivers 40 spaced apart along the length of cables 38, and steeringdevices 42. It is explicitly recognized that seismic streamers 36 may bespaced apart equidistant one another, at irregular spacings, or anycombination thereof as desired. Steering devices 42 assist inmaintaining relative lateral distances between seismic receivers 40 asdesired.

As can be seen in FIG. 5, rearward-most group of seismic receivers 46span a distance d_(r), which is greater than the distance d_(f), thedistance spanned by the front-most group of seismic receivers 44. Incertain embodiments, the seismic streamer system 34 is in a flaredconfiguration when the lateral distance (d_(r)) between the outer-most,rearward-most seismic receivers 40 a,b is at least about 2 percent, atleast about 5 percent, at least about 10 percent, at least about 20percent, or in the range of about 30 to about 400 percent greater thanthe lateral distance (d_(f)) between the outer-most, front-most seismicreceivers 40 c,d.

When coupling seismic streamers to one or more marine vessels, the term“coupled to,” as used herein, refers to both direct and indirectcoupling such that an intervening element may exist between seismicstreamer and the marine vessel. As the term is used herein, only theterm “coupled to” requires at most an operable coupling of the seismicstreamers to a marine vessel.

One or more methods of the present invention may be implemented via aninformation handling system. For purposes of this disclosure, aninformation handling system may include any instrumentality or aggregateof instrumentalities operable to compute, classify, process, transmit,receive, retrieve, originate, switch, store, display, manifest, detect,record, reproduce, handle, or utilize any form of information,intelligence, or data for business, scientific, control, or otherpurposes. For example, an information handling system may be a personalcomputer, a network storage device, or any other suitable device and mayvary in size, shape, performance, functionality, and price. Theinformation handling system may include random access memory (RAM), oneor more processing resources such as a central processing unit (CPU orprocessor) or hardware or software control logic, ROM, and/or othertypes of nonvolatile memory. Additional components of the informationhandling system may include one or more disk drives, one or more networkports for communication with external devices as well as various inputand output (I/O) devices, such as a keyboard, a mouse, and a videodisplay. The information handling system may also include one or morebuses operable to transmit communications between the various hardwarecomponents.

As an example of one implementation of an information handling systemfor use in combination with the present invention, seismic data iscommunicated to information handling system 90, which is comprised ofprocessor 92, data storage device 91, display 94, and optionalinterpreter 93. Seismic data collected from seismic receivers 40 may becommunicated to information handling system 90 to processor 92 forstorage in data storage device 91. The seismic data may then beinterpreted by interpreter 93. Alternatively, in some embodiments,interpreter 93 is located external to information handling system 90 andconsequently, this step may be performed at a later date when seismicdata is later retrieved from data storage device 91.

FIG. 6 illustrates a simplified overhead depiction of a marine seismicacquisition system with seismic streamers shown in yet anotherflared-configuration and more specifically, a trumpet-shaped system ofvariable length seismic streamers exhibiting a rearwardly increasingrate of flaring in flared section 52 of seismic streamer system 50. Asused herein, the “flared section” of a seismic streamer system refers tothe section of the seismic streamer system that is in a flaredconfiguration. Thus, for the seismic streamer system 34 of FIG. 5, theentire length of the streamer system 34 would be considered a flaredsection. For the seismic streamer system 50 of FIG. 6, however, theflared section 52 has a length (l_(f)) that is less than the totallength (l_(t)) of the seismic streamer system 50. As depicted in FIG. 3the seismic streamer system 50 can also include a non-flared/straightsection 54 that exhibits substantially constant streamer spacing overits length (l_(b)).

In accordance with various embodiments of the present invention, thelength (l_(a)) of the flared section of a seismic streamer system can beat least 5 percent, at least 10 percent, at least 20 percent, at least40 percent, at least 60 percent, at least 80 percent, or at least 100percent of the total length (l_(t)) of the seismic streamer system. Inaccordance with certain embodiments, the flared section of a seismicstreamer system can exhibit an average lateral spacing between adjacentseismic streamers that increases rearwardly at a rate of at least 0.001meters (lateral) per meter (longitudinal), at least 0.002 meters permeter, at least 0.005 meters per meter, at least 0.01 meters per meter,at least 0.05 meters per meter, or at least 0.1 meters per meter.

Many other configurations are possible as would be recognized by aperson of ordinary skill in the art with the benefit of this disclosure.U.S. patent application Ser. No. 12/167,683, filed Jul. 3, 2008, titled“Marine Seismic Acquisition with Controlled Streamer Flaring,” theentire disclosure of which is incorporated by reference, describes anumber of possible streamer configurations, streamer elements, anddevices, all of which may be used in combination with embodiments of thepresent invention.

FIGS. 7A-7C illustrates additional sail line survey paths in accordancewith various embodiments of the present invention. Although sinusoidaland half-ellipse survey paths have been specifically illustrated above,many other survey paths are suitable in combination with the presentinvention. Indeed, any survey path comprising a plurality of linked orconnected curved paths are suitable for use with the present invention.Examples of suitable survey paths include, but are not limited to, aseries of linked half-ellipses, a series of linked half-sine waves, aseries of alternating linked half-ellipses, survey paths having asinusoidal wave form, or any combination thereof. As used herein, theterm “alternating” refers to survey paths in which each crest wave isinverted with respect to the previous wave, in an alternatingcrest/trough pattern as illustrated, for example, by the waveform shownin The amplitude and/or frequency or pitch of such survey paths may beconstant or variable as desired depending on various factors, includingthe region to be surveyed, available equipment and resources, andexternal conditions such as wind direction and speed and ocean currents.

FIGS. 7A, 7B, 7C and 7D show some non-limiting examples of survey pathssuitable for use with the present invention. In particular, FIG. 7Ashows two survey paths 711 and 712, each of constant wavelength λ. Here,wavelength λ is defined as the distance of the survey path that spans atleast two crests, two troughs, or as indicated in FIG. 7A, the distancebetween two zero crossings.

Survey path 711 is formed by a series of linked half-sine waves, whereassurvey path 712 is formed by a series of linked half-sine waves that areinverted with respect to survey path 711. In one embodiment, one marinevessel could travel along a portion of survey path 711 while a secondmarine vessel travels along a portion of survey path 712. In this way,two marine vessels acting in cooperation with one another may completethe combination of survey paths 711 and 712.

It is explicitly recognized that either or both of survey paths 711 and712 may be surveyed by any combination of paths that when taken togetherform one or both of survey paths 711 and 721. For example, as shown inFIG. 7B, one marine vessel could travel along survey path 721 whileanother marine vessel travels along survey path 722. Additionally, whenmore than one marine vessel cooperates with another marine vessel, it isexplicitly recognized that the survey paths may be completedsimultaneously, sequentially, time-lagged off-set with one another, orany combination thereof.

FIG. 7C shows an example of an irregular survey path 731. Here, surveypath 731 follows a series of linked curved paths wherein the amplitudeand wavelength of each curved path vary as desired.

FIG. 7D shows yet another example of a survey path in accordance withone embodiment of the present invention. Here, survey path 741 follows aseries of linked, deviated survey paths. The term, “deviated,” as usedherein refers to any series of survey paths, the combination of whichdeviates from a straight path. Examples of suitable deviated surveypaths in accordance with the present invention include, but are notlimited to, square wave survey paths, triangle survey paths, any of theaforementioned survey paths, or any combination thereof.

It is explicitly recognized that any of the elements and features ofeach of the devices described herein are capable of use with any of theother devices described herein with no limitation. Furthermore, it isexplicitly recognized that the steps of the methods herein may beperformed in any order except unless explicitly stated otherwise orinherently required otherwise by the particular method.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations and equivalents are considered withinthe scope and spirit of the present invention. Also, the terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

What is claimed is:
 1. A method for acquiring seismic data for a subsearegion of the earth, comprising: providing first and second marinevessels each with a plurality of seismic streamers, wherein theplurality of seismic streamers are coupled to the marine vessels fortowing and each seismic streamer comprises a plurality of marine seismicreceivers spaced apart along the length of each seismic streamer;providing a marine seismic source; introducing the marine seismic sourceinto a marine environment in range of the marine seismic receivers;towing the seismic streamers through the marine environment such thatthe first marine vessel and the seismic streamers coupled thereto travelsubstantially along a first series of linked deviated paths and thesecond marine vessel and the seismic streamers coupled thereto travelsubstantially along a second series of linked deviated paths invertedwith respect to the first series of linked deviated paths; exciting themarine seismic source within range of both the first and second marinevessels while towing the seismic streamers so as to cause acoustic waveenergy to travel through the marine environment into the subsea regionof the earth; allowing the acoustic wave energy to reflect and refractfrom the subsea region so as to form reflected and refracted waveenergy; and detecting the reflected and refracted wave energy with themarine seismic receivers of both the first and second marine vesselssurveying in cooperation with one another so as to form detected seismicdata.
 2. The method of claim 1, wherein the deviated paths includesquare wave survey paths.
 3. The method of claim 1, wherein the deviatedpaths include triangle survey paths.
 4. The method of claim 1, furthercomprising maintaining, for each of the vessels, the plurality ofseismic streamers in a flared configuration.
 5. The method of claim 1,further comprising steering one or more of the seismic streamers into aflared configuration.
 6. The method of claim 1, further comprising:storing the detected seismic data in a data storage device; processingthe detected seismic data with one or more interpreters so as to produceseismic information representative of the subsea region of the earth;and graphically displaying seismic information on a display.
 7. Themethod of claim 1, wherein the marine seismic source is coupled to themarine vessel.
 8. The method of claim 1, wherein the second series oflinked deviated paths intersect or directly interface with the firstseries of linked deviated paths.
 9. The method of claim 1, wherein themarine seismic source includes a plurality of sources.
 10. The method ofclaim 1, further comprising maintaining, for each of the vessels, theplurality of seismic streamers in a flared configuration, wherein theflared configuration is characterized by a rearward lateral seismicreceiver span that is at least about 20 percent greater than a forwardlateral seismic receiver span.
 11. The method of claim 1, furthercomprising maintaining, for each of the vessels, at least 5 percent of atotal length of the seismic streamers in a flared configuration.
 12. Themethod of claim 1, further comprising maintaining, for each of thevessels, at least 80 percent of a total length of the seismic streamersin a flared configuration.
 13. The method of claim 1, further comprisingmaintaining, for each of the vessels, the plurality of seismic streamersin a flared configuration, wherein the flared configuration ischaracterized by an average lateral spacing between adjacent seismicstreamers increasing rearward at a rate of at least 0.001 lateral metersper longitudinal meters.
 14. The method of claim 1, further comprisingmaintaining, for each of the vessels, the plurality of seismic streamersin a flared configuration, wherein the flared configuration ischaracterized by an average lateral spacing between adjacent seismicstreamers increasing rearward at a rate of at least 0.1 lateral metersper longitudinal meters.